The removal of carbon dioxide from mixed gas streams is of great industrial importance and commercial value. Carbon dioxide is a ubiquitous and inescapable by-product of the combustion of hydrocarbons and there is growing concern over its accumulation in the atmosphere and its potential role in global climate change. If laws and regulations driven by environmental factors are enacted, capture and sequestration may be required. While existing methods of CO2 capture have been satisfactory for the scale in which they have so far been used, future uses on the far larger scale required for significant reductions in atmospheric CO2 emissions from major stationary combustion sources, such as power stations fired by fossil fuels, makes it necessary to improve the energy efficiency of the processes used for the removal of CO2 from gas mixtures, and thereby to lower the cost of CO2 capture. According to data developed by the Intergovernmental Panel on Climate Change, power generation produces approximately 78% of stationary source emissions of CO2 with other industries such as cement production (7%), refineries (6%), iron and steel manufacture (5%), petrochemicals (3%), oil and gas processing (0.4%), and the biomass industry (bioethanol and bioenergy) (1%) making up the bulk of the total, illustrating the very large differences in scale between power generation on the one hand and all other uses on the other. To this must be added the individual problem of the sheer volumes of gas which will need to be treated. Flue gases generally consist mainly of nitrogen from combustion air, with the CO2, nitrogen oxides, and other emissions such as sulfur oxides making up relatively smaller proportions of the gases which require treatment. Typically, the wet flue gases from fossil fuel power stations typically contain about 7-15 vol % of CO2, depending on the fuel, with natural gas yielding the lowest amounts and hard coals the highest.
Cyclic CO2 sorption technologies such as Pressure Swing Absorption (PSA) and Temperature Swing Absorption (TSA) using liquid sorbents are well-established. The sorbents mostly used include liquid solvents, as in amine scrubbing processes, although solid sorbents are also used in PSA and TSA processes. Liquid amine sorbents dissolved in water are probably the most common sorbents. Amine scrubbing is based on the chemical reaction of CO2 with amines to generate carbonate/bicarbonate and carbamate salts—the aqueous amine solutions chemically trap the CO2 by the formation of one or more ammonium salts, such as carbamate, bicarbonate, and carbonate. The reaction tends to be reversible, and these salts can be converted back to the original components upon suitable adjustment of conditions, usually temperature, enabling the regeneration of the free amine at moderately elevated temperatures. Commercially, amine scrubbing typically involves contacting the acid gas (CO2 and/or H2S) containing gas stream with an aqueous solution of one or more simple alkanolamines selected preferentially, as the hydroxyl group confers greater solubility in water for both the amine(s) and for the reaction product(s). Alkanolamines, such as monoethanolamine (MEA), diethanolamine (DEA), and triethanolamine (TEA), as well as a limited set of hindered amines, are currently used in commercial processes. The cyclic sorption process requires high rates of gas-liquid heat exchange, the transfer of large liquid inventories between the sorption and regeneration zones, and high energy requirements for the regeneration of amine solutions. The corrosive nature of amine solutions containing the sorbed CO2, which forms the amine-CO2 reaction products, can also be an issue. Without further improvement, these difficulties would limit the economic viability of the aqueous amine scrubbing processes in very large scale applications.
The cyclic sorption processes using aqueous sorbents typically require a significant temperature differential in the gas stream between the sorption and desorption (regeneration) parts of the cycle. In conventional aqueous amine scrubbing methods, relatively low temperatures (e.g., less than 50° C.) are required for CO2 uptake, with an increase to a temperature above about 100° C. (e.g., 120° C.) required for desorption. The heat required to maintain the thermal differential is a major factor in the cost of the process. With the need to regenerate the solution at temperatures above 100° C., the high latent heat of vaporization of the water (˜2260 kJ/Kg at ˜100° C.) obviously makes a significant contribution to the total energy consumption. If CO2 capture is to be conducted on the larger scale appropriate to use in power plants, more effective and economical separation techniques need to be developed.
Another area where more efficient CO2 separation processes are needed is in enhanced oil recovery (EOR), where CO2 is re-injected into the gas or liquid hydrocarbon deposits to maintain reservoir pressure. With the advanced age of many producing reservoirs worldwide and the ever-increasing challenge of meeting demand, the expanding use of EOR methods is becoming more widespread. Typically, the source of carbon dioxide for EOR is the producing hydrocarbon stream itself, which may contain anywhere from less than 5% to more than 80% of CO2. Other options are capture of CO2 from the flue gases of various combustion sources and pre-combustion capture of CO2 from shifted syngas produced in fuel gasification processes.
The use of sterically hindered amines for CO2 capture was proposed by Sartori and Savage in “Sterically Hindered Amines for CO2 Removal from Gases,” Ind. Eng. Chem. Fundamen., 1983, 22(2), 239-249, pointing out that sterically hindered amines can have unique capacity and rate advantages in CO2 sorption processes—their rich solutions can be desorbed to a greater extent than their non-substituted and/or less hindered counterparts, thus producing a leaner solution (lower total carbamate/bicarbonate/carbonate concentration), which tends to result in a greater mass transfer upon reabsorption. A limited number of processes using sterically hindered amines as alternatives to MEA, DEA, and TEA are used commercially for CO2 capture; examples include the KS-1™ Process from Mitsubishi Heavy Industries and Kansai Electric Power Co and the ExxonMobil Flexsorb® Process, which uses sterically hindered amine(s) for selective H2S separation. Processes using solid sorbents are also known; they may avoid some of the limitations of amine scrubbing, such as large capital investment and high regeneration energy intensity, but they suffer from a lack of sorbents having sufficiently selective CO2 sorption under the humid conditions present in combustion flue gas and from the difficulty in designing gas/solid contactors to process large volumes of gas at high throughput rates.
U.S. Pat. No. 5,618,506 describes a process for removing carbon dioxide from gases. In a first aspect, CO2 is removed from a gas stream by contacting the gas stream with a solution containing a first alkanolamine that optionally also contains a second amine compound. The first alkanolamine is generically described as being present in an amount of 15-65 wt %, while the second amine is generically described as being present in an amount of 1.5-50 wt %. One option described for the first alkanolamine is 2-methylamino-2-methyl-1-propanol. One option described for the second amine compound is piperazine. All of the process is described as occurring in solution, and there is no mention of forming a precipitate or slurry during the process of removing the carbon dioxide.
European Patent No. EP 0 879 631 describes a process for removing carbon dioxide from gases. A gas stream containing CO2 is contacted with a solution that contains a tertiary amine, such as 2-dimethylamino ethanol, that also contains a secondary amine, such as piperazine, where the concentration of the tertiary amine is within 10 wt % of the concentration that would result in maximum CO2 absorption if the tertiary amine was used alone, and where the concentration of the secondary amine is at least about 10 wt %.